When a hydrocarbon-bearing, subterranean reservoir formation does not have enough permeability or flow capacity for the hydrocarbons to flow to the surface in economic quantities or at optimum rates, hydraulic fracturing or chemical (usually acid) stimulation is often used to increase the flow capacity. A wellbore penetrating a subterranean formation typically consists of a metal pipe (casing) cemented into the original drill hole. Holes (perforations) are placed to penetrate through the casing and the cement sheath surrounding the casing to allow hydrocarbon flow into the wellbore and, if necessary, to allow treatment fluids to flow from the wellbore into the formation.
Hydraulic fracturing consists of injecting fluids (usually viscous shear thinning, non-Newtonian gels or emulsions) into a formation at such high pressures and rates that the reservoir rock fails and forms a plane, typically vertical, fracture (or fracture network) much like the fracture that extends through a wooden log as a wedge is driven into it. Granular proppant material, such as sand, ceramic beads, or other materials, is generally injected with the later portion of the fracturing fluid to hold the fracture(s) open after the pressure is released. Increased flow capacity from the reservoir results from the easier flow path left between grains of the proppant material within the fracture(s). In chemical stimulation treatments, flow capacity is improved by dissolving materials in the formation or otherwise changing formation properties.
Application of hydraulic fracturing as described above is a routine part of petroleum industry operations as applied to individual target zones of up to about 60 meters (200 feet) of gross, vertical thickness of subterranean formation. When there are multiple or layered reservoirs to be hydraulically fractured, or a very thick hydrocarbon-bearing formation (over about 60 meters), then alternate treatment techniques are required to obtain treatment of the entire target zone. The methods for improving treatment coverage are commonly known as “diversion” methods in petroleum industry terminology.
When multiple hydrocarbon-bearing zones are stimulated by hydraulic fracturing or chemical stimulation treatments, economic and technical gains are realized by injecting multiple treatment stages that can be diverted (or separated) by various means, including mechanical devices such as bridge plugs, packers, downhole valves, sliding sleeves, and baffle/plug combinations; ball sealers; particulates such as sand, ceramic material, proppant, salt, waxes, resins, or other compounds; or by alternative fluid systems such as viscosified fluids, gelled fluids, foams, or other chemically formulated fluids; or using limited entry methods. These and all other methods and devices for temporarily blocking the flow of fluids into or out of a given set of perforations will be referred to herein as “diversion agents.”
In mechanical bridge plug diversion, for example, the deepest interval is first perforated and fracture stimulated, then the interval is typically isolated by a wireline-set bridge plug, and the process is repeated in the next interval up. Assuming ten target perforation intervals, treating 300 meters (1,000 feet) of formation in this manner would typically require ten jobs over a time interval of ten days to two weeks with not only multiple fracture treatments, but also multiple perforating and bridge plug running operations. At the end of the treatment process, a wellbore clean-out operation would be required to remove the bridge plugs and put the well on production. The major advantage of using bridge plugs or other mechanical diversion agents is high confidence that the entire target zone is treated. The major disadvantages are the high cost of treatment resulting from multiple trips into and out of the wellbore and the risk of complications resulting from so many operations in the well. For example, a bridge plug can become stuck in the casing and need to be drilled out at great expense. A further disadvantage is that the required wellbore clean-out operation may damage some of the successfully fractured intervals.
One alternative to using bridge plugs is filling the portion of wellbore associated with the just fractured interval with fracturing sand, commonly referred to as the Pine Island technique. The sand column in the wellbore essentially plugs off the already fractured interval and allows the next interval to be perforated and fractured independently. The primary advantage is elimination of the problems and risks associated with bridge plugs. The disadvantages are that the sand plug does not give a perfect hydraulic seal and it can be difficult to remove from the wellbore at the end of all the fracture stimulations. Unless the well's fluid production is strong enough to carry the sand from the wellbore, the well may still need to be cleaned out with a work-over rig or coiled tubing unit. As before, additional wellbore operations increase costs, mechanical risks, and risks of damage to the fractured intervals.
Another method of diversion involves the use of particulate materials, granular solids that are placed in the treating fluid to aid diversion. As the fluid is pumped, and the particulates enter the perforations, a temporary block forms in the zone accepting the fluid if a sufficiently high concentration of particulates is deployed in the flow stream. The flow restriction then diverts fluid to the other zones. After the treatment, the particulate is removed by produced formation fluids or by injected wash fluid, either by fluid transport or by dissolution. Commonly available particulate diverter materials include benzoic acid, napthalene, rock salt (sodium chloride), resin materials, waxes, and polymers. Alternatively, sand, proppant, and ceramic materials, could be used as particulate diverters. Other specialty particulates can be designed to precipitate and form during the treatment.
Another method for diverting involves using viscosified fluids, viscous gels, or foams as diverting agents. This method involves pumping the diverting fluid across and/or into the perforated interval. These fluid systems are formulated to temporarily obstruct flow to the perforations due to viscosity or formation relative permeability decreases; and are also designed so that at the desired time, the fluid system breaks down, degrades, or dissolves (with or without adding chemicals or other additives to trigger such breakdown or dissolution) such that flow can be restored to or from the perforations. These fluid systems can be used for diversion of matrix chemical stimulation treatments and fracture treatments. Particulate diverters and/or ball sealers are sometimes incorporated into these fluid systems in efforts to enhance diversion.
Another possible process is limited entry diversion in which the entire target zone of the formation to be treated is perforated with a very small number of perforations, generally of small diameter, so that the pressure loss across those perforations during pumping promotes a high, internal wellbore pressure. The internal wellbore pressure is designed to be high enough to cause all of the perforated intervals to fracture simultaneously. If the pressure were too low, only the weakest portions of the formation would fracture. The primary advantage of limited entry diversion is that there are no inside-the-casing obstructions like bridge plugs or sand to cause problems later. The disadvantage is that limited entry fracturing often does not work well for thick intervals because the resulting fracture is frequently too narrow (the proppant cannot all be pumped away into the narrow fracture and remains in the wellbore), and the initial, high wellbore pressure may not last. As the sand material is pumped, the perforation diameters are often quickly eroded to larger sizes that reduce the internal wellbore pressure. The net result can be that not all of the target zone is stimulated. An additional concern is the potential for flow capacity into the wellbore to be limited by the small number of perforations.
Some of the problems resulting from failure to stimulate the entire target zone or using mechanical methods that require multiple wellbore operations and wellbore entries that pose greater risk and cost as described above may be alleviated by using limited, concentrated perforated intervals diverted by ball sealers. The zone to be treated could be divided into sub-zones with perforations at approximately the center of each of those sub-zones, or sub-zones could be selected based on analysis of the formation to target desired fracture locations. The fracture stages would then be pumped with diversion by ball sealers at the end of each stage. Specifically, 300 meters (1,000 feet) of gross formation might be divided into ten sub-zones of about 30 meters (about 100 feet) each. At the center of each 30 meter (100 foot) sub-zone, ten perforations might be shot at a density of three shots per meter (one shot per foot) of casing. A fracture stage would then be pumped with proppant-laden fluid followed by ten or more ball sealers, at least one for each open perforation in a single perforation set or interval. The process would be repeated until all of the perforation sets were fractured. Such a system is described in more detail in U.S. Pat. No. 5,890,536, issued Apr. 6, 1999.
Historically, all zones to be treated in a particular job that uses ball sealers as the diversion agent have been perforated prior to pumping treatment fluids, and ball sealers have been employed to divert treatment fluids from zones already broken down or otherwise taking the greatest flow of fluid to other zones taking less, or no, fluid prior to the release of ball sealers. Treatment and sealing theoretically proceeded zone by zone depending on relative breakdown pressures or permeabilities, but problems were frequently encountered with balls prematurely seating on one or more of the open perforations outside the targeted interval and with two or more zones being treated simultaneously. Furthermore, this technique presumes that each perforation interval or sub-zone would break down and fracture at sufficiently different pressure so that each stage of treatment would enter only one set of perforations.
The primary advantages of ball sealer diversion are low cost and low risk of mechanical problems. Costs are low because the process can typically be completed in one continuous operation, usually during just a few hours of a single day. Only the ball sealers are left in the wellbore to either flow out with produced hydrocarbons or drop to the bottom of the well in an area known as the rat (or junk) hole. The primary disadvantage is the inability to be certain that only one set of perforations will fracture at a time so that the correct number of ball sealers are dropped at the end of each treatment stage. In fact, optimal benefit of the process depends on one fracture stage entering the formation through only one perforation set and all other open perforations remaining substantially unaffected during that stage of treatment. Further disadvantages are lack of certainty that all of the perforated intervals will be treated and of the order in which these intervals are treated while the job is in progress. When the order of zone treatment is not known or controlled, it is not possible to ensure that each individual zone is treated or that an individual stimulation treatment stage has been optimally designed for the targeted zone. In some instances, it may not be possible to control the treatment such that individual zones are treated with single treatment stages.
To overcome some of the disadvantages that may occur during stimulation treatments when multiple zones are perforated prior to pumping treatment fluids, an alternative mechanical diversion method has been developed that involves the use of a coiled tubing stimulation system to sequentially stimulate multiple intervals with separate treatment. As with conventional ball sealer diversion, all intervals to be treated are perforated prior to pumping the stimulation treatment. Then coiled tubing is run into the wellbore with a mechanical “straddle-packer-like” diversion tool attached to the end. This diversion tool, when properly placed and actuated across the perforations, allows hydraulic isolation to be achieved above and below the diversion tool. After the diversion tool is placed and actuated to isolate the deepest set of perforations, stimulation fluid is pumped down the interior of the coiled tubing and exits flow ports placed in the diversion tool between the upper and lower sealing elements. Upon completion of the first stage of treatment, the sealing elements contained on the diversion tool are deactivated or disengaged, and the coiled tubing is pulled upward to place the diversion tool across the second deepest set of perforations and the process is continued until all of the targeted intervals have been stimulated or the process is aborted due to operational upsets.
This type of coiled tubing stimulation apparatus and method have been used to hydraulically fracture multiple zones in wells with depths up to about 8,000 feet. However, various technical obstacles, including friction pressure losses, damage to sealing elements, depth control, running speed, and potential erosion of coiled tubing, currently limit deployment in deeper wells.
Excess friction pressure is generated when pumping stimulation fluids, particularly proppant-laden and/or high viscosity fluids, at high rates through longer lengths of coiled tubing. Depending on the length and diameter of the coiled tubing, the fluid viscosity, and the maximum allowable surface hardware working pressures, pump rates could be limited to just a few barrels per minute; which, depending on the characteristics of a specific subterranean formation, may not allow effective placement of proppant during hydraulic fracture treatments or effective dissolution of formation materials during acid stimulation treatments
Erosion of the coiled tubing could also be a problem as proppant-laden fluid is pumped down the interior of the coiled tubing at high velocity, including the portion of the coiled tubing that remains wound on the surface reel. The erosion concerns are exacerbated as the proppant-laden fluid impinges on the “continuous bend” associated with the portion of the coiled tubing placed on the surface reel.
Most seal elements (e.g., “cup” seal technology) currently used in the coiled tubing stimulation operations described above could experience sealing problems or seal failure in deeper wells as the seals are run past a large number of perforations at the higher well temperatures associated with deeper wells. Since the seals run in contact with or at a minimal clearance from the pipe wall, rough interior pipe surfaces and/or perforation burrs can damage the sealing elements. Seals currently available in straddle-packer-like diversion tools are also constructed from elastomers which may be unable to withstand the higher temperatures often associated with deeper wells.
Running speed of the existing systems with cup seals is generally on the order of 15 to 30 feet-per-minute running downhole to 30 to 60 feet-per-minute coming uphole. For example, at the lower running speed, approximately 13 hours would be required to reach a depth of 12,000 feet before beginning the stimulation. Given safety issues surrounding nighttime operations, this slow running speed could result in multiple days being required to complete a stimulation job. If any problems are encountered during the job, tripping in and out of the hole could be very costly because of the total operation times associated with the slow running speeds.
Depth control of the coiled tubing system and straddle-packer-like diversion tool also becomes more difficult as depth increases, such that placing the tool at the correct depth to successfully execute the stimulation operation may be difficult. This problem is compounded by shooting the perforations before running the coiled tubing system in the hole. The perforating operation uses a different depth measurement device (usually a casing collar locator system) than is generally used in the coiled tubing system.
In addition, the coiled tubing method described above requires that all of the perforations be placed in the wellbore in a separate perforating operation prior to pumping the stimulation job. The presence of multiple perforation sets open above the diversion tool can cause operational difficulties. For example, if the proppant fracture from the current zone were to grow vertically and/or poor quality cement is present behind pipe, the fracture could intersect the perforation sets above the diversion tool such that proppant could “dump” back into the wellbore on top of the diversion tool and prevent further tool movement. Also, it could be difficult to execute circulation operations if multiple perforation sets are open above the diversion tool. For example, if the circulation pressures exceed the breakdown pressures associated with the perforations open above the diversion tool, the circulation may not be maintained with circulation fluid unintentionally lost to the formation.
A similar type of stimulation operation may also be performed using jointed tubing and a workover rig rather than a coiled tubing system. Using a diversion tool deployed on jointed tubing may allow for larger diameter tubing to reduce friction pressure losses and allow for increased pump rates. Also, concerns over erosion and tubing integrity may be reduced when compared to coiled tubing since heavier wall thickness jointed tubing pipe may be used and jointed tubing would not be exposed to plastic deformation when run in the wellbore. However, using this approach would likely increase the time and cost associated with the operations because of slower pipe running speeds than those possible with coiled tubing.
To overcome some of the limitations associated with completion operations that require multiple trips of hardware into and out of the wellbore to perforate and stimulate subterranean formations, methods have been proposed for “single-trip” deployment of a downhole tool string to allow for fracture stimulation of zones in conjunction with perforating. Specifically, these methods propose operations that may minimize the number of required wellbore operations and time required to complete these operations, thereby reducing the stimulation treatment cost. These proposals include 1) having a sand slurry in the wellbore while perforating with overbalanced pressure, 2) dumping sand from a bailer simultaneously with firing the perforating charges, and 3) including sand in a separate explosively released container. These proposals all allow for only minimal fracture penetration surrounding the wellbore and are not adaptable to the needs of multi-stage hydraulic fracturing as described herein.
Accordingly, there is a need for an improved method and apparatus for individually treating each of multiple intervals of a subterranean formation penetrated by a wellbore while maintaining the economic benefits of multi-stage treatment. There is also a need for a method and apparatus that can economically reduce the risks inherent in the currently available stimulation treatment options for hydrocarbon-bearing formations with multiple or layered reservoirs or with thickness exceeding about 60 meters (200 feet) while ensuring that optimal treatment placement is performed with a mechanical diversion agent that positively directs treatment stages to the desired location.